Gas flow rate measurement

ABSTRACT

Once an oil well has been drilled and is producing, it is desirable to monitor the rate at which oil or gas is being delivered. It is particularly useful to know when there is a change in a fluid&#39;s output rate, for that can indicate problems with the well. This monitoring is known as “production logging”. Prior to the introduction of horizontal well drilling, most wells were either vertical or only slightly deviated. However, many present-day wells have long horizontal or nearly-horizontal portions, and the techniques used to measure flow in vertical wells are not applicable to horizontal wells. Moreover, any flow rate measurement technique to be used downhole should take account not only of the several sorts of “lined” wells but also the “barefoot” ones. 
     The invention seeks to satisfy this need for a technique that can be employed with all these sorts of completed well by utilizing a pair of correlated spaced sensors (that can detect “directly” the difference between gas and liquid (oil and/or water), which sensor pair is carried on a logging tool positioned within the borehole itself such that the individual sensors are disposed so as to be actually in the path of any gas bubbles likely to be in the fluid. The correlated output of the sensor pair allows a determination of the gas flow velocity, and if at the same time measurements are taken that provides an indication of the hold-up of the gas bubbles there may by calculation be determined the flow rate both of the gas and of the fluid.

FIELD OF THE INVENTION

This invention relates to gas flow rate measurement, and concerns inparticular the measurement of the flow of gas in a multiphase gas andliquid environment in a nearly-horizontal ascending borehole.

BACKGROUND OF THE INVENTION

Once a well—especially an oil- or gas-well—has been drilled and isproducing the sought-after fluid(s), it is desirable to monitor the rateat which each fluid (such as oil or gas, or, in a multiphase well,mixtures of these with each other and/or with water) is being delivered.It is particularly useful to know when there is a change in a fluid'soutput rate, for that can indicate problems with the well—for instance,that the well is coming to the end of its useful life, or that materialis leaking in (or out) of the well before it gets to the surface. Thismonitoring is known as “production logging”—definable as the measurementof fluid flow rates as a function of depth in an oil or gas well—and hasbeen in use for many years.

The primary motivation of production logging is to monitor productionflow rates of the various fluids (oil, water and gas), and to locatedepths in the well of entry of unwanted fluids. Once the entry depthsare located, various steps are available to shut off the unwanted entry.

Prior to the introduction of horizontal well drilling, most wells wereeither vertical or only slightly deviated (from 0 to at most 60 degreesfrom the vertical), and so there was little need to measure flow ratesin nearly-horizontal wells. However, many present-day wells have longhorizontal or nearly-horizontal portions (at 80 or 90 degrees to thevertical), and, because the conditions in horizontal wells are verydifferent from those in vertical or only-slightly-deviated wells, thetechniques used to measure flow in these latter types of well are simplynot applicable to horizontal wells. One example of such an inapplicabletechnique involves the use of a gradiomanometer; this is a device whichdetermines the density of a fluid by measuring the pressure gradientcaused by gravity in a column of fluid—but since in horizontal wellsgravity acts at right angles to the line of the wellbore, this techniquesimply does not work in them. Another inapplicable technique involvesthe use of a so-called “spinner”—a small propeller/turbine driven by thepassing fluid. The spinner conventionally used in production logging tomeasure flow rate does not give an interpretable response in horizontalwells, where it responds primarily to the liquid, and hardly at all tothe gas.

The invention solves this problem by utilising—by taking advantageof—some of those very features which are peculiar to horizontal wells,such as “slug flow”.

Of course, it is not unknown in many fields—and even in the oilindustry—to take measurements of multiphase flow in nearly-horizontalpipelines. However, to date most of these pipelines have been surfacepipelines, such as might convey the fluid from a well head to a storagesystem, or from one part of a refinery to another, and these are verydifferent from the nearly-horizontal underground boreholes involved inactually producing the fluids in the first place. Down a well thepressures are enormous—several hundreds of atmospheres—and any gasbubbles are necessarily compressed into a relatively small size. On thesurface, however, there is relatively-speaking no compressive pressure,so that those gas bubbles expand to a relatively large size—and becauseof these large amounts of free gas the flow is often “slug flow”, withliquid-rich regions of flow alternating with gas-rich regions. Thistime-varying nature of the flow has been suggested for use to measurethe velocity of the various flow components; for example, one proposalinvolves beaming gamma rays into and through the pipes from externalsources, and using correlated external detectors to measure slugvelocity and, by the gamma ray attenuation, the volume fraction of theflow.

As in surface pipelines, so in nearly-horizontal but ascending wellsfree gas flows along and up the well typically as bubbles along theupper side of the borehole (in descending wells, the gas forms astratified layer rather than bubbles). Unfortunately, for severalreasons it is difficult to use the “surface” type of measurement systemactually in a borehole; taking measurements downhole is different fromtaking them at or near the surface in a number of significant ways. Inthe first place—and as mentioned above—because of the higher pressuresin a borehole much of the gas downhole is dissolved in the liquid, andthe size of the gas bubbles is much smaller, typically not nearlyfilling the pipe. Such small amounts of gas are difficult to detect withgamma attenuation devices. Also, systems which require that sourcesand/or detectors be placed outside the flow obviously cannot be used forborehole flow measurements, which must have all sources and/or detectorswithin the borehole (or within any liner, if there is one [this isdiscussed further below]). Additionally, there may be problems downholethat stem from the borehole having a liner—typically a “slotted” linerand the normal surface measurement techniques are unable to cope withthe downhole problem of fluid flow in the annulus between the liner andthe borehole surface proper. Added to this, of course, are thedifficulties and dangers associated with the radioactive sources neededfor the gamma ray generation; these cannot be turned off, and anyapparatus which uses them can be a safety hazard.

Wells can be configured or “completed” in a number of ways. Sometimes afairly tight-fitting steel liner—a large aperture tube—is placed withinthe borehole to line its sides, and cement is squeezed between the linerand the borehole wall to complete that lining. Holes are then made inthe liner and cement with explosive charges (to let the production fluidout of the underground geological formation through which the boreholeis passing at that point), and this combination is called a “cementedcompletion”. On the other hand, sometimes there is employed a “slottedliner”—a steel liner with holes or slots pre-installed. In this case, nocement is used, so the liner tube is fairly loose within the borehole,and no additional holes are necessary. Such a slotted well gives rise toparticular difficulties because of the freedom of the well fluid to flowboth within the liner and also in the gap—the annulus—between the linerand the borehole walls. Finally, sometimes—usually in an effort to savemoney—no liner at all is installed in the borehole; this is called a“barefoot completion”.

Any flow rate measurement technique to be used downhole should ifpossible take account not only of the several sorts of “lined” wells butalso the “barefoot” ones. Accordingly, a production logging tool willpreferably make accurate flow measurements in any of these types ofcompletions. This is particularly difficult in the case of a slottedliner, where as noted there will be fluid flowing both in the liner andin the annulus therearound.

SUMMARY OF THE INVENTION

The invention seeks to satisfy this need for a technique that can beemployed with all these sorts of completed well by using a modifiedversion of the techniques employed in above-ground flow ratemeasurement, and utilising a pair of correlated spaced sensors that candetect “directly” the difference between gas and liquid (oil and/orwater), which sensor pair is carried on a logging tool positioned withinthe borehole itself such that the individual sensors are disposed so asto be actually in the path of any gas bubbles likely to be in the fluid.The correlated output of the sensor pair allows a determination of thegas flow velocity, and if at the same time measurements are taken thatprovides an indication of the hold-up of the gas bubbles—in other words,the size of the bubbles as an area proportion of the boreholecross-sectional area—there may by calculation be determined the flowrate both of the gas and of the fluid.

In one aspect, therefore, this invention provides a method ofdetermining downhole the flow rate—in nearly-horizontal sections of awell borehole—of gas within a multiphase fluid containing a mixture ofgas and liquid, in which method:

there is positioned within the length of borehole of interest a loggingtool carrying thereon a pair of sensors spaced apart a known distanceaxially along the tool (and thus along the borehole), each sensor beingable “directly” to detect the difference between gas and liquid, andbeing so mounted on the tool that, with the tool positioned within theborehole, the sensor is disposed to be actually in the path of any gasbubbles likely to be in the fluid;

the output of the sensor pair is correlated to allow an identificationof individual gas bubbles passing from one sensor to the other, and forthe time taken by this passage to be measured, and from adistance-over-time calculation there is then determined the gas bubblevelocity;

there is determined the time-averaged hold-up of the gas within themultiphase fluid; and

by a hold-up-times-borehole area-times-gas bubble velocity calculationthere is then determined the gas flow rate within that length of theborehole.

The invention also provides apparatus for use in the defined method ofdetermining downhole the gas flow rates of a multiphase gas/liquidfluid, the apparatus comprising:

a logging tool to be positioned within the length of borehole ofinterest, the tool carrying thereon a pair of sensors spaced apart aknown distance axially along the tool (and thus along the borehole),each sensor being able in use “directly” to detect the differencebetween gas and liquid, and being so mounted on the tool that, with thetool positioned within the borehole, the sensor is disposed to beactually in the path of any gas bubbles likely to be in the fluid; and

correlation and calculation means

whereby the output of the sensor pair may be correlated to allow anidentification of individual gas bubbles passing from one sensor to theother, and for the time taken by this passage to be measured, and from adistance-over-time calculation there may then be determined the gasbubble velocity,

whereby there may be determined the time-averaged hold-up of the gaswithin the multiphase fluid, and

whereby by a hold-up-times-borehole area-times-gas bubble velocitycalculation there may then be determined the gas flow rate within thatlength of the borehole.

The invention is for determining downhole the flow rate—innearly-horizontal lengths of a well borehole—of the gas in a multiphasefluid containing a mixture of gas and liquid. As indicated above,“nearly horizontal” means from around 80 to 90 degrees to the vertical,though the method may still find a use in well lengths which are lessthan 80 degrees—say, 75 or even 70 degrees—to the vertical. Of course,the well may have other sections which are vertical or nearly verticalto which the nearly-horizontal length(s) is/or joined; most commonly awell may start vertical or near-vertical, and then curve over to becomehorizontal or near-horizontal as it enters and passes through theoil-bearing underground formation of interest.

The invention is for use with wells producing multiphase fluidscontaining a mixture of gas and liquid (which latter may be oil or wateralone or, as is more likely, oil and water together). Well fluids canhave extensively varying component proportions—in particular, there arevery wide ranges of the fraction of water in the liquid—but typicallynot more than about 25% of the borehole volume is occupied by gas.

In the invention there is positioned within the length of borehole ofinterest a logging tool carrying thereon a pair of sensors. The sensorsmay be of any type provided that they can directly determine thedifference between gas and liquid, by measuring some property of the twothat differs in a suitably significant manner. Such sensors includefibre optic reflectance sensors and resistivity sensors.

The preferred variety of sensor for measuring the property change is afibre optic reflectance sensor, which measures the refractive index ofthe fluid in a very small region at the tip of the sensor. This type ofsensor can detect changes with time in the refractive index of gas andliquids. Since these sensors are very small, they can be placed verynear the top of the borehole or liner, and so are sensitive to verysmall bubbles of gas.

A second type of sensor is that known as a local resistivity probe. Alocal resistivity probe consists of two closely spaced electrodes and ameans for measurement of the electrical resistivity of whatevermaterial—gas or liquid—is positioned or passes between the twoelectrodes. When the electrodes are placed in water, a relatively lowresistivity is recorded (in oil wells the water is usually brine, loadedwith salt and other ionic materials, and is really quite a goodconductor of electricity), while, when placed in hydrocarbons, eitheroil or gas, a relatively high resistivity is recorded. These sensors donot directly detect gas as they cannot distinguish gas from oil, butthey can directly detect changes in the water level as a gas bubblepasses by, and hence indirectly they detect the gas. As such, thesesensors require some water to be present in order to measure gasvelocity. Nevertheless, experience has shown that this type of sensorprovides a useful measurement of gas velocity if the water-to-liquidratio is at least 0.15:1.

Other types of sensors are possible. The main requirements are that thesensor be capable of operating inside a borehole environment, and thatit measure some property of the fluid which changes with time as the gasbubble passes by.

In the invention there is employed a logging tool carrying thereon apair of sensors (M1,M2) spaced apart a known distance (l_(d)) axiallyalong the tool (and thus along the borehole; one sensor is the upstreamsensor, the other the downstream one). This along-axis separation isused so that there can be detected the time-separated passing of aparticular bubble first by one sensor and then by the other, so as togive a means of calculating the speed of the bubble as it moves with thestream of fluid from one to the other. Logging tools are typically about50 ft (15 m) long, and a satisfactory separation of the two sensors isfrom less than half an inch (about a centimetre) up to around 10 ft (3m), preferably around 7½ ft (somewhat over 2 m). Smaller separationsmake the detection rather inaccurate, while greater separations requirethe logging tool to be too long.

On the logging tool, each sensor is so mounted on the tool that, withthe tool positioned within the borehole, the sensor is disposed to beactually in the path of any gas bubbles likely to be in the fluid. Thisis an obvious requirement if the sensors are directly to detect somedifference between the fluid's phases, and is generally achieved byarranging for the logging tool itself to be fixedly orientated withinthe borehole, and then for the disposition of the sensors relative tothe tool to be predetermined such that in use they will indeed be placedin the bubble path—right at the top side of the horizontal length ofborehole as required. It is common for logging tools to need to havesuch a fixed orientation, and this needs no further comment here,although it may nevertheless be helpful to note that one technique forarranging this is to include a joint in the tool which allows the bottomhalf of the tool (containing the sensors) to swivel, and an offsetweight which then orients by gravity the bottom half of the tool so thatthe sensors are actually positioned adjacent the upper surface of thehorizontal length of borehole.

In the invention the logging tool is carrying thereon a pair of sensorsspaced apart a known distance axially along the tool, and the output ofthe sensor pair is correlated to allow an identification of individualgas bubbles passing with the stream of fluid from one sensor to theother. The idea of correlation to identify occurrences of one sort oranother is well-known, and the techniques employed to achieve this donot require any discussion here. Nevertheless, one useful correlationtechnique appropriate in the present invention is that known as FourierTransform Cross Correlation, which is described in, for example, thebook Numerical Recipes, by W H Press (et al).

Once the correlation has allowed the identification of a particularbubble as it passes by first the upstream sensor and then the downstreamsensor, then there may be determined, from the sensor measurements, thetime (T) taken for this passage. By a distance-over-time calculationthere may then be determined the gas bubble velocity (V_(sg)=l_(d)/T).

The invention utilises the gas bubble velocity (V_(sg)) to determine thegas flow rate (q_(g)) by a hold-up-times-borehole area-times-gas bubblevelocity . . . q_(g)=H_(g)×A×V_(sg), but of course to do this there mustalso be known the time-averaged hold-up H_(g) of the gas. In practice,the time-averaged hold-up is obtained from averaging over manysequential measurements from a “hold-up tool” which measures “snapshots”of the gas hold-up at specific instants in time. Then the gas flowrate—more accurately, the time-averaged gas volume flow rate—isnumerically equal to the product of the velocity of the bubbles, whichdoesn't change significantly with time over the relevant period, and thetime-averaged cross sectional area of the pipe occupied by the gasbubbles, which latter is the product of the area of the pipe and thetime-averaged hold-up. And hence the equation given above.

The gas hold-up may be determined by any convenient method, such as apulsed neutron tool (described, for instance, in Pulsed-NeutronThree-Phase-Holdup Measurements in Horizontal Wells, JPT Nov 97, p1256-1257), but for an oil-producing well is preferably effected with anarray of optical reflectance probes, which array is of sufficientresolution—has enough individual probes appropriately disposed—to mapthe position of gas within a cross section of the borehole. For gas andwater flows (no oil), an array of local resistivity probes may be usedto map gas location, as well. Other methods of mapping the position ofgas within the liner, such as x-ray imaging, are also possible. However,x-ray techniques are less desirable as they either use a radioisotopesource and are therefore a radiation hazard, or they use an electronicx-ray generator which is expensive and failure prone.

One of the intended purposes of this invention is to measure thevelocity of gas bubbles, and thus the gas flow rate, in either acemented or a barefoot completion in ascending horizontal conditions,and it will be evident that the method as so far described enables suchmeasurements to be accomplished. Another, however, is to provide abetter measurement of gas bubble velocity, and thus gas flow rate, in aslotted lined well; to achieve this desideratum the inventive method asso far defined requires an addition to its use to measure what happenswithin the liner, namely the provision of a method, employable at thesame time, which enables a measurement of what is also happening outsidethe liner—that is, in the annulus between the liner and the boreholewall proper (in such a slotted well most of the bubbles travel in theannulus, while the liquid remains in the liner core because its greaterviscosity makes it hard for it to pass through the slots). Such an addedmethod is one in which there is employed a sensor/detector system thatcan “look” through the liner into the annulus space, and is typified byequipment of the type presently utilised in reservoir saturationmeasurements, such as the Reservoir Saturation Tool (RST). This sort ofequipment incorporates a neutron generator positioned within the linerand radiating neutrons through the liner and the annulus therearound andinto the borehole formation, there causing gamma ray emission, thegenerator being coupled with gamma ray detection apparatus, with twoseparate detectors spaced along the line of the borehole, so as tomeasure the gamma rays radiated back through the gas/liquid fluid inboth the annulus and the liner core. Such equipment can enable adetermination of the total gas flow rate along the borehole, being acombination of that in the liner core and that in the annulus, and ifthis is coupled with independently-obtained information about the linercore gas flow rate itself then by a calculation—of the formerannulus/core rate combination minus the latter core rate alone—thenclearly there is provided figures for the annulus gas flow rate on itsown.

In another aspect, therefore, the invention provides a method ofdetermining downhole the gas flow rate in a borehole that utilises aslotted liner, in which method:

there is determined, by a method of the invention as already described,the liner gas flow rate within the liner core; and

there is additionally employed on the logging tool a neutron generatorcapable of radiating generated neutrons though the liner and into theborehole formation, together with a pair of gamma ray detectors spacedapart a known distance axially along the tool (and thus along theborehole), each gamma ray detector being able to detectformation-originating gamma rays created by the generated neutrons andso signal the difference between gas and liquid;

the output of the gamma ray detector pair is correlated to allow anidentification of individual gas bubbles passing from one detector tothe other, and for the time taken by this passage to be measured, andfrom a distance-over-time calculation there is then determined the gasbubble velocity;

there is determined the time-averaged hold-up of the gas within themultiphase fluid; and

by a hold-up-times-borehole area-times-gas bubble velocity calculationthere is then determined the total gas flow rate, within both the linercore and also the annulus, for that length of the borehole;

whereafter, by a total gas flow rate-minus-liner gas flow ratecalculation there is determined the annulus gas flow rate.

The invention also provides apparatus for determining downhole the gasflow rate in a borehole that utilises a slotted liner, which apparatusis as previously defined and additionally includes:

on the logging tool a neutron generator capable of radiating generatedneutrons though the liner and into the borehole formation, together witha pair of gamma ray detectors spaced apart a known distance axiallyalong the tool (and thus along the borehole), each gamma ray detectorbeing able to detect formation-originating gamma rays created by thegenerated neutrons and so signal the difference between gas and liquid;

together with correlation and calculation means as aforesaid butapplicable to the output from the gamma ray detector pair, and whereby,by a total gas flow rate-minus-liner gas flow rate calculation, theremay be determined the annulus gas flow rate.

The just-defined preferred form of the invention is, as noted, thepreviously-defined method (or apparatus) with the addition of theemployment on the logging tool of a neutron generator (capable ofradiating generated neutrons though the liner and into the boreholeformation) together with a pair of spaced gamma ray detectors each ableto detect formation-originating gamma rays. These additional detectorcomponents are used just like the sensors in the basic method—theiroutput is correlated to allow an identification of individual gasbubbles, the passage time taken by a particular bubble is measured,there is determined the gas bubble velocity, and from a knowledge of thetime-averaged hold-up of the gas there is calculated the total gas flowrate, from which may be subtracted the liner gas flow rate to give theannulus gas flow rate. None of this needs any further discussion at thistime. However, it will be useful to say a little about the combinationof neutron generator and gamma ray detectors.

A preferred type of generator is an electronic generator of 14 MeVneutrons of the type employing a deuteron-triton fusion reaction andcommonly used in the oil industry. The neutron generator is coupled witha pair of gamma ray detectors, preferably high-speed scintillationdetectors using, for example, GSO or NaI(T1) scintillators. The pair ofgamma ray detectors is conveniently spaced a short distance from theneutron generator along the direction of flow, typically about 0.5 to 2ft (0.15 to 0.6 m), consistent with the physical size of the generatorand the detectors. In operation, neutrons from the neutron generatorinelastically scatter from nuclei in the surrounding formation,generating a source of gamma rays external to the borehole. Some of thegamma rays then pass back into the borehole, where they are attenuatedby the fluid therein—but significantly more by the liquid than by thegas. Each gamma ray detector then detects, and counts, the receivedgamma rays, and in this case it is the count rate in the detector whichis the property which changes with time as the gas bubble passes by. Twogamma ray detectors at different spacings from the neutron generator areused to make the velocity measurement, their count rates beingcorrelated to allow identification of each particular bubble, but onlyone neutron generator is used. Note that the electronic generator doesnot suffer from the radiation safety problem because it emits noradiation when it is turned off.

BRIEF DESCRIPTION OF THE DRAWINGS

An embodiment of the invention is now described, though by way ofillustration only, with reference to the accompanying diagrammaticDrawings in which:

FIG. 1 shows gas/liquid slug flow along an above-ground horizontalpipeline;

FIG. 2 shows gas/liquid bubble flow along an underground horizontallength of unlined (barefoot) borehole;

FIG. 3 shows gas/liquid bubble flow along an underground horizontallength of slotted lined borehole;

FIG. 4 shows the apparatus used for the measurement of gas/liquid bubbleflow along an underground horizontal length of borehole in accordancewith a preferred embodiment of the present invention.

DETAILED DESCRIPTION OF THE INVENTION

Illustrated in FIG. 1 is an example of gas/liquid slug flow along anabove-ground horizontal pipeline (10). The gas (11) is in the form oflarge “bubbles” (12) occupying a relatively large proportion of thepipe's volume, and the liquid (13) is bunched up into “slugs” (14).

FIG. 2 shows much the same sort of situation, but this time thegas/liquid bubble flow is in an underground horizontal length of unlined(barefoot) borehole (20). Here, because of the very much higherpressure, the gas bubbles (22) are much smaller, and disposed right atthe top surface of the bore 20, and the oil 13 effectively completelyfills the bore.

FIG. 3 shows much the same sort of situation as shown in FIG. 2, buthere the gas/liquid bubble flow is in an underground horizontal lengthof slotted lined borehole 20. As can be seen, the borehole has looselylocated within it a metal liner—a tube (35)—that has been formed with amyriad of longitudinal slots (as 36). The liner 35 is a loose fit withinthe borehole 20, so that an annular space (37) is left around it. Thisannular space fills with liquid 13 and also with some gas bubbles (as32) disposed along the top surface. The core volume of the liner alsocontains a few bubbles (as 38) disposed along its top inner surface.

FIG. 4 shows the apparatus used in accordance a preferred embodiment ofwith the present invention for the measurement of gas/liquid bubble flowalong an underground horizontal length of slotted lined borehole (likethat in FIG. 3).

The apparatus comprises a logging tool (generally 41) having an elongatebody (42) with two spaced spring-loaded spacer arm pairs (as 43) thatkeep it centrally located and suitably orientated (by means not shown)axially of a borehole 20 passing through an underground formation (as44). The borehole shown is a slotted lined borehole, with a slottedliner (45: the slots are not shown) making a loose fit inside theborehole 20 (and thus having therearound an annulus 46). Flowing alongthe borehole (from right to left, as viewed) is a multiphase productionfluid that is mostly liquid—oil and water—but with some bubbles of gastherein. As shown in FIG. 3, some of the bubbles (as 47) are in theannulus 46, while others (as 48) are actually in the liner core.

The logging tool 41 carries two different sets of bubble “detection”gear. First, here shown on each of the upper of the tool spacer arms 43,is a local probe (49 n or 49 f) that directly senses and signals thedifference between the gas and the liquid, but only in respect of thegas bubbles 48 within the liner core volume. In operation the outputsfrom these sensors 49 is supplied (by means not shown) to correlationand calculation means (not shown) which use them to work out the speedof the bubbles 48 along the borehole. Thus, for any particular gasbubble the output of the far sensor 49 f should match the slightly lateroutput of the near sensor 49 n—which identifies the bubble—and, knowingthe distance between the two sensors and the time between the twomatching outputs there can be calculated the speed of the bubble.

Second, disposed long the body 42 of the tool there is aneutron-generator (401) and a pair of associated gamma ray detectors(402 n, 402 f); the pair 402 is spaced upstream of the generator 401,and the two individual detectors 402 are spaced one from the other. Inoperation the neutron-generator 401 generates neutrons which radiateaway (for example, along the heavy dashed lines) through the liquid 13,through the gas 48,47, through the liner 45 and into and through theformation 44. In the latter some of the neutrons strike atomstherewithin, and cause the emission of gamma rays (gamma) thatradiate—“shine”—back into borehole. As these gamma rays travel back intothe borehole they pass through the liquid 13, the gas bubbles 47,48, andthe liner 45, and by the time they—those, that is, travelling in theright direction—reach the detectors 402 they have been attenuated bytheir passage through these materials. The gas attenuates less than—theliquid, so that the detectors output a signal that is larger when thegamma rays came back through a gas bubble (and is larger the larger thebubble) than when they came back on a path missing the bubbles and thusonly through the liquid. This output signal can therefore be used—in thecorrelator and calculator (not shown) to which it is sent (by means notshown)—first to identify a particular gas bubble 47,48 as it moves alongthe borehole, and then to calculate the speed of the bubble. Thus, forany particular gas bubble the output of the far detector 402 f shouldmatch the slightly later output of the near detector 402 n—whichidentifies the bubble—and, knowing the distance between the twodetectors and the time between the two matching outputs there can becalculated the speed of the bubble.

It will be seen, incidentally, that the incoming gamma rays pass throughboth the annulus bubbles 48 and the liner core volume bubbles 47, sothat the output of the two detectors 402 includes information about thetotal amount of gas travelling along the borehole. Thus, by asubtraction of the corresponding within-liner information from the localprobe sensors 49 there can be deduced the flow rate for the gastravelling in the annulus.

What is claimed is:
 1. A method of determining downhole innearly-horizontal sections of a well borehole the flow rate of gaswithin a multiphase fluid containing a mixture of gas and liquid, themethod comprising the steps of; positioning within a length of aborehole of interest a logging tool carrying thereon a pair of localsensors spaced apart a known distance axially along the tool and thusalong the borehole, each sensor being able to detect the differencebetween gas and liquid, and being mounted on arms extendible from a mainbody of the tool such that, with the tool positioned within theborehole, the sensors are disposed to be actually in a path of any gasbubbles likely to be in the fluid; correlating the output of the pair ofsensors to allow an identification of individual gas bubbles passingfrom one sensor to the other; measuring the time taken for gas bubblesto pass from one sensor to the other; determining from adistance-over-time calculation a gas bubble velocity; determining atime-averaged hold-up of the gas within the multiphase fluid; anddetermining by a hold-up-times-borehole area-times-gas bubble velocitycalculation the gas flow rate within the length of the borehole.
 2. Amethod as claimed in claim 1, in which the sensors are fibre opticreflectance sensors or resistivity sensors.
 3. A method as claimed inclaim 1, wherein the pair of sensors are separated by a distance of 0.01m to 3 m.
 4. A method as claimed in claim 1, in which the time-averagedhold-up is obtained from averaging over many sequential measurementsfrom a hold-up tool which measures snapshots of the gas hold-up atspecific instants in time, and the hold-up tool utilizes either an arrayof optical reflectance probes or an array of local resistivity probes tomap the position of gas within a cross section of the borehole.
 5. Amethod as claimed in claim 1, wherein, to provide a better measurementof the gas bubble velocity, and thus the gas flow rate, in a slottedlined well, there is additionally obtained a measurement of what ishappening in an annulus between a liner and a wall of the borehole.
 6. Amethod as claimed in claim 5, further comprising the steps of:determining a liner gas flow rate within a liner core; employing on thelogging tool a neutron generator capable of radiating generated neutronsthough the liner and into a formation beyond the wall of the borehole,together with a pair of gamma ray detectors spaced apart a knowndistance axially along the tool and thus along the borehole, each gammaray detector being able to detect formation-originating gamma rayscreated by the generated neutrons and so to thereby distinguish betweengas and liquid; correlating output of the pair of gamma ray detectors toallow an identification of individual gas bubbles passing from onedetector to the other; measuring the time taken for gas bubbles to passfrom one detector to the other determining from a distance-over-timecalculation the gas bubble velocity; determining the time-averagedhold-up of the gas within the multiphase fluid; determining by ahold-up-times-borehole area-times-gas bubble velocity calculation thetotal gas flow rate, within both the liner core and also the annulus,for that length of the borehole; and determining by a total gas flowrate-minus-liner gas flow rate calculation an annulus gas flow rate. 7.A downhole apparatus designed to determine downhole gas flow rates of amultiphase gas/liquid fluid, the apparatus comprising: a logging tool tobe positioned within a length of borehole of interest, the tool carryingthereon a pair of local sensors spaced apart a known distance axiallyalong the tool and thus along the borehole, each sensor being able inuse to detect the difference between gas and liquid, and being mountedon arms extendible from a main body of the tool such that, with the toolpositioned within the borehole, the sensors are disposed to be actuallyin a path of any gas bubbles likely to be in the fluid; and a processoradapted to correlate output of the pair of sensors to allow anidentification of individual gas bubbles passing from one sensor to theother, measure the time taken for gas bubble to pass from one sensor tothe other, and determine from a distance-over-time calculation a gasbubble velocity, whereby there may be determined a time-averaged hold-upof the gas within the multiphase fluid, and whereby by ahold-up-times-borehole area-times-gas bubble velocity calculation theremay then be determined the gas flow rate within the length of theborehole.
 8. An apparatus as claimed in claim 7 and for determiningdownhole gas flow rate in a borehole that utilizes a slotted liner,which apparatus is as previously defined and additionally includes: onthe logging tool a neutron generator capable of radiating generatedneutrons though the liner and into a formation beyond the wall of theborehole, together with a pair of gamma ray detectors spaced apart aknown distance axially along the tool and thus along the borehole, eachgamma ray detector being able to detect formation-originating gamma rayscreated by the generated neutrons and to thereby distinguish between gasand liquid; wherein the processor is adapted to correlate output fromthe pair of gamma ray detectors, and whereby, by a total gas flowrate-minus-liner gas flow rate calculation, there may be determined anannulus gas flow rate.